During the drilling and completion of oil and gas wells, it may be necessary to engage in ancillary operations, such as monitoring the operability of equipment used during the drilling process or evaluating the production capabilities of formations intersected by the wellbore. For example, after a well or well interval has been drilled, zones of interest are often tested to determine various formation properties such as permeability, fluid type, fluid quality, formation temperature, formation pressure, bubblepoint and formation pressure gradient. These tests are performed in order to determine whether commercial exploitation of the intersected formations is viable and how to optimize production.
Wireline formation testers (WFT) and drill stem testing (DST) have been commonly used to perform these tests. The basic DST test tool consists of a packer or packers, valves or ports that may be opened and closed from the surface, and two or more pressure-recording devices. The tool is lowered on a work string to the zone to be tested. The packer or packers are set, and drilling fluid is evacuated to isolate the zone from the drilling fluid column. The valves or ports are then opened to allow flow from the formation to the tool for testing while the recorders chart static pressures. A sampling chamber traps clean formation fluids at the end of the test. WFTs generally employ the same testing techniques but use a wireline to lower the test tool into the well bore after the drill string has been retrieved from the well bore, although WFT technology is sometimes deployed on a pipe string. The wireline tool typically uses packers also, although the packers are placed closer together, compared to drill pipe conveyed testers, for more efficient formation testing. In some cases, packers are not used. In those instances, the testing tool is brought into contact with the intersected formation and testing is done without zonal isolation across the axial span of the circumference of the borehole wall.
WFTs may also include a probe assembly for engaging the borehole wall and acquiring formation fluid samples. The probe assembly may include an isolation pad to engage the borehole wall. The isolation pad seals against the formation and around a hollow probe, which places an internal cavity in fluid communication with the formation. This creates a fluid pathway that allows formation fluid to flow between the formation and the formation tester while isolated from the borehole fluid.
In order to acquire a useful sample, the probe must stay isolated from the relative high pressure of the borehole fluid. Therefore, the integrity of the seal that is formed by the isolation pad is critical to the performance of the tool. If the borehole fluid is allowed to leak into the collected formation fluids, a non-representative sample will be obtained and the test will have to be repeated.
Examples of isolation pads and probes used in WFTs can be found in Halliburton's DT, SFTT, SFT4, and RDT tools. Isolation pads that are used with WFTs are typically rubber pads affixed to the end of the extending sample probe. The rubber is normally affixed to a metallic plate that provides support to the rubber as well as a connection to the probe. These rubber pads are often molded to fit within the specific diameter hole in which they will be operating.
With the use of WFTs and DSTs, the drill string with the drill bit must be retracted from the borehole. Then, a separate work string containing the testing equipment, or, with WFTs, the wireline tool string, must be lowered into the well to conduct secondary operations. Interrupting the drilling process to perform formation testing can add significant amounts of time to a drilling program.
The formation pressure measurement accuracy of drill stem tests and, especially, of wireline formation tests may be affected by filtrate invasion and mudcake buildup because significant amounts of time may have passed before a DST or WFT engages the formation. Mud filtrate invasion occurs when the drilling mud fluids displace formation fluids. Because the mud filtrate ingress into the formation begins at the borehole surface, it is most prevalent there and generally decreases further into the formation. When filtrate invasion occurs, it may become impossible to obtain a representative sample of formation fluids or, at a minimum, the duration of the sampling period must be increased to first remove the drilling fluid and then obtain a representative sample of formation fluids. The mudcake is made up of the solid particles that are plastered to the side of the well by the circulating drilling mud during drilling. The prevalence of the mudcake at the borehole surface creates a “skin.” Thus there may be a “skin effect” because formation testers can only extend relatively short distances into the formation, thereby distorting the representative sample of formation fluids due to the filtrate. The mudcake also acts as a region of reduced permeability adjacent to the borehole. Thus, once the mudcake forms, the accuracy of reservoir pressure measurements decreases, affecting the calculations for permeability and producibility of the formation.
Another testing apparatus is the formation tester while drilling (FTWD) tool. Typical FTWD formation testing equipment is suitable for integration with a drill string during drilling operations. Various devices or systems are used for isolating a formation from the remainder of the borehole, drawing fluid from the formation, and measuring physical properties of the fluid and the formation. For example, the FTWD may use a probe similar to a WFT that extends to the formation and a small sample chamber to draw in formation fluids through the probe to test the formation pressure. To perform a test, the drill string is stopped from rotating and the test procedure, similar to a WFT described above, is performed.
Formation fluids of interest consist of liquid hydrocarbons of varying densities, typically less than that of water. On the other hand drilling fluids are usually of higher average density containing weighting material such as barite, calcium carbonate, hematite, etc. in solution or suspension. Hydrocarbon molecules consist of varying combinations of hydrogen, carbon, and oxygen atoms, resulting in fluid densities less than that of water from a few percent to several tens of percent. Borehole fluids typically are more dense than water, by factors of between one and two. Significantly higher densities than water in this range are more likely, because fluid samples are taken at target depths where the pressures are usually highest for the particular well. For the purpose of well control, the borehole fluid densities are increased to offset the effects of these downhole pressures. Usually a significant contrast between the borehole fluid density and the density of the formation fluids results.
In addition, the higher borehole fluid densities are obtained by including weighting materials mentioned above. The presence of these materials affects not only the density of the fluid but the spectral characteristics as well.
As mentioned, the representative sample of the formation fluid may be distorted by the present of filtrate and may also be distorted by the presence of borehole fluid if a proper seal is not obtained before taking the same or if the borehole fluid otherwise makes it into the sample chamber. Thus, borehole fluid is a possible “pollutant” in the early phases of the extraction, and the sample drawn from the formation should be relatively free of borehole fluid material to maintain an accurate measurement. Systems have been proposed that analyze, or identify, the sample fluid to determine the fluid identification. Such systems typically use optical sensors or sensors that measure other physical properties of the fluid. However, such systems do not necessarily provide a measure of the homogeneity of the fluid being tested.